In a wide range of well and formation treatment methods it is desirable to use various materials such as solids for downhole operations or procedures, and then later to remove or destroy the materials, after they have fulfilled their function, to restore properties to the wellbore and/or subterranean formations such as permeability for oil and gas production, or to activate the materials to fulfill a function such as a viscosity breaker or breaker aid.
Fluid loss control agents provide one example. When placing fluids in oilfield applications, fluid loss into the formation is a major concern. Fluid loss reduces the efficiency of the fluid placement with respect to time, fluid volume, and equipment. Thus, controlling fluid loss is highly desired. There are many oilfield applications in which filter cakes are needed in the wellbore, in the near-wellbore region or in one or more strata of the formation. Such applications are those in which, without a filter cake, fluid would leak off into porous rock at an undesirable rate during a well treatment. Such treatments include drilling, drill-in, completion, stimulation (for example, hydraulic fracturing or matrix dissolution), sand control (for example gravel packing, frac-packing, and sand consolidation), diversion, scale control, water control, and others. When the filter cake is within the formation it is typically called an “internal” filter cake; otherwise it is called an “external” filter cake. Typically, after these treatments have been completed the continued presence of the filter cake is undesirable or unacceptable.
Conventional water-based drilling and completion fluids, for example, often rely on polymers to provide viscosity and fluid loss control. This approach requires acid, oxidizer or enzyme to remove polymer residue and filter cake buildup, to reduce the extent of formation damage. It is, for example, a common practice for drilling fluid to use sized calcium carbonate as a bridging agent, in which case acid plus a corrosion inhibitor package is subsequently required for filter cake removal. The overall drilling/completion strategy based on polymer fluids is often operationally cumbersome, can lack long-term stability, can employ corrosive chemicals, and/or can be prone to cause formation damage.
Hydraulic fracturing, gravel packing, or fracturing and gravel packing in one operation (called, for example frac and pack or frac-n-pack, or frac-pack treatments), are used extensively to stimulate the production of hydrocarbons, water and other fluids from subterranean formations. These operations involve pumping a slurry of “proppant” (natural or synthetic materials that prop open a fracture after it is created) in hydraulic fracturing or “gravel” in gravel packing. In low permeability formations, the goal of hydraulic fracturing is generally to form long, high surface area fractures that greatly increase the magnitude of the pathway of fluid flow from the formation to the wellbore. In high permeability formations, the goal of a hydraulic fracturing treatment is typically to create a short, wide, highly conductive fracture, in order to bypass near-wellbore damage done in drilling and/or completion, to ensure good fluid communication between the rock and the wellbore and also to increase the surface area available for fluids to flow into the wellbore. Gravel is also a natural or synthetic material, which may be identical to, or different from, proppant. Gravel packing is used for “sand” control. Sand is the name given to any particulate material, such as clays, from the formation that could be carried into production equipment. Gravel packing is a sand-control method used to prevent production of formation sand, in which, for example a steel screen is placed in the wellbore and the surrounding annulus is packed with prepared gravel of a specific size designed to prevent the passage of formation sand that could foul subterranean or surface equipment and reduce flows. The primary objective of gravel packing is to stabilize the formation while causing minimal impairment to well productivity. Sometimes gravel packing is done without a screen. High permeability formations are frequently poorly consolidated, so that sand control is needed. Therefore, hydraulic fracturing treatments in which short, wide fractures are wanted are often combined in a single continuous (“frac and pack”) operation with gravel packing. For simplicity, reference may be made below to any one of hydraulic fracturing, fracturing and gravel packing in one operation (frac and pack), or gravel packing, and include them all; the term “proppant” may likewise refer to and include gravel and the term “gravel” proppant.
Solid, substantially insoluble, or sparingly or slowly soluble materials (that may be called fluid loss additives and/or filter cake components) are typically added to the fluids used in these treatments to form filter cakes, although sometimes soluble (or at least highly dispersed) components of the fluids (such as polymers or crosslinked polymers) may form some or all of the filter cakes. Removal of the filter cake is typically accomplished either by a mechanical means (scraping, jetting, or the like), by subsequent addition of a fluid containing an agent (such as an acid, a base, an oxidizer, or an enzyme) that dissolves at least a portion of the filter cake, or by manipulation of the physical state of the filter cake (by emulsion inversion, for example). These removal methods usually require a tool or addition of another fluid (for example to change the pH or to add a chemical). This can sometimes be accomplished in the wellbore but normally cannot be done in a proppant or gravel pack. Sometimes the operator may rely on the flow of produced fluids (which will be in the opposite direction from the flow of the fluid when the filter cake was laid down) to loosen the filter cake or to dissolve at least a part of the filter cake (for example if it is a soluble salt). However, these methods require fluid flow and often result in slow or incomplete filter cake removal. Sometimes a breaker can be incorporated in the filter cake but these must normally be delayed (for example by esterification or encapsulation) and they are often expensive and/or difficult to place and/or difficult to trigger.
In hydraulic fracturing, a first, viscous fluid called a “pad” is typically injected into the formation to initiate and propagate the fracture and often to contribute to fluid loss control. The choice of the pad fluid depends upon the nature of the subsequently injected fluid, the nature of the formation, and the desired results and attributes of the stimulation job. This is typically followed by a second fluid designed primarily to carry the proppant that keeps the fracture open after the pumping pressure is released. Occasionally, hydraulic fracturing is done with a second fluid that is not highly viscosified; this choice is made primarily to save chemical costs and/or as a way to reduce the deleterious effect of polymers described below. This technique, sometimes called a “water-frac” involves using extremely low polymer concentrations, so low that they cannot be effectively crosslinked, throughout the job. This alternative has a major drawback: since there is inadequate viscosity to carry much proppant, high pump rates must be used and only very small concentrations of proppant (pounds mass proppant added per gallon of fluid (“PPA”)) can be used. Very little proppant will be placed in the fracture to keep it open after the pumping is stopped.
Pads and fracturing or gravel packing fluids are usually viscosified in one of three ways. If the injected fluid is an oil, it is gelled with certain additives designed for the purpose, such as certain aluminum and phosphate compounds. If the fluid is water or brine, for hydraulic or acid fracturing, it is gelled with a polymer (usually a polysaccharide like guar, usually crosslinked with a boron, zirconium or titanium compound), or with a viscoelastic surfactant fluid system (“VES”) that can be formed using certain surfactants that form appropriately sized and shaped micelles. VES's are popular because they leave very clean proppant or gravel packs, but they do not form a filter cake by themselves. Polymers, especially crosslinked polymers, often tend to form a “filter cake” on the fracture face, that is, they coat out on the fracture face as some fluid leaks off, provided that the rock pores are too small to permit entry of the polymer or crosslinked polymer. Some filter cake is generally desirable for fluid loss control. This process of filter cake formation is also called wallbuilding. VES fluids without fluid loss additives do not form filter cakes as a result of leak-off. VES leak-off control, in the absence of fluid loss additives, is viscosity controlled, i.e., the resistance due to the flow of the viscous VES fluid through the formation porosity limits the leak-off rate. The viscosity controlled leak-off rate can be high in certain formation permeabilities because the highly shear-thinning fluid has a low apparent viscosity in high flow velocity areas. Reducing the flow velocity (by correspondingly reducing the pressure gradient or simply as a result of the same injected volumetric flow rate leaking off into the formation through a greater surface area as the fracture grows in length and height) will allow micelle structure to reassemble and will result in regeneration of viscosity and fluid loss control. Fluid loss control may not always be optimal with VES systems, especially in higher permeability formations. On the other hand, polymers have two major deficiencies: a) the filter cake, if left in place, can impede subsequent flow of hydrocarbons into the fracture and then into the wellbore, and b) polymer or crosslinked polymer will be left in the fracture itself, impeding or cutting off flow, either by physically blocking the flow path through the proppant pack or by leaving a high viscosity fluid in the fracture. VES fluids do not form a filter cake or leave solids in the fracture. VES fluids, therefore, leave a cleaner, more conductive and, therefore, more productive fracture than polymer-based fluids. They are easier to use because they require fewer components and less surface equipment, but they may be less efficient (in terms of fluid loss) than polymers, depending upon the formation permeability and the specific VES system. It would be desirable to make use of VES fluid systems more efficient in terms of fluid loss.
To overcome high fluid loss in polymeric and VES-based fluids (in particular in hydraulic fracturing fluids, gravel carrier fluids, and fluid loss control pills), various fluid loss control additives have been proposed. Silica, mica, and calcite, alone, in combination, or in combination with starch, are known to reduce fluid loss in polymer-based fracturing fluids, by forming a relatively water-impermeable filter cake on the formation face, as described in U.S. Pat. No. 5,948,733. Use of these fluid loss control additives alone in a VES-based fluid, however, has been observed to give only modest decreases in fluid loss, as described in U.S. Pat. No. 5,929,002. The poor performance of these conventional fluid loss additives is typically attributed to the period of high leak-off (spurt) before a filter cake is formed and to the formation of a filter cake permeable to the VES-based fluid.
Instead of conventional fluid loss additives and filter cake formation, it is known to treat a subterranean formation by pumping a colloidal suspension of small particles in a viscoelastic surfactant fluid system; see for example U.S. Patent Application Publication No. 2005-0107265 assigned to the assignee of the present application. The colloidal suspension and the viscoelastic surfactant interact to form structures that effectively bridge and block pore throats. Colloidal suspensions are typically dispersions of discrete very small particles, spherical or elongated in shape, charged so that the repulsion between similarly charged particles stabilizes the dispersion. Disturbance of the charge balance, due for instance to removing water, changing the pH or adding salt or water-miscible organic solvent, causes the colloidal particles to aggregate, resulting in the formation of a gel. These particles are typically less than 1 micron in size, and typically in the range of from about 10 to about 100 nanometers. The dispersion is prepackaged as a liquid, transparent in the case of relatively low concentrations of particles, becoming opalescent or milky at higher concentrations. In any case, the dispersion may be handled as a liquid, which greatly simplifies the dosage.
The use of a hydrolysable polyester material for use as a fluid loss additive for fluid loss control has previously been proposed for polymer-viscosified fracturing fluids. After the treatment, the fluid loss additive degrades and so contributes little damage. Further, degradation products of such materials have been shown to cause delayed breaking of polymer-viscosified fracturing fluids. U.S. Pat. No. 4,715,967 discloses the use of polyglycolic acid (PGA) as a fluid loss additive to temporarily reduce the permeability of a formation. SPE paper 18211 discloses the use of PGA as a fluid loss additive and gel breaker for crosslinked hydroxypropyl guar fluids. U.S. Pat. No. 6,509,301 describes the use of acid forming compounds such as PGA as delayed breakers of surfactant-based vesicle fluids, such as those formed from the zwitterionic material lecithin. The preferred pH of these materials is above 6.5, more preferably between 7.5 and 9.5.
Since VES fluid systems cause negligible damage, it would be desirable to use a fluid loss additive that is compatible with the VES system and also causes negligible damage. The use of polyglycolic acid and similar materials as a fluid loss additive for VES fluid systems is described in U.S. patent application Ser. No. 11/159,023, filed Jun. 22, 2005, hereby incorporated herein by reference in its entirety. Briefly, polyglycolic acid and similar materials most often degrade by a mechanism of hydrolysis, catalyzed by acid or base. However, these fluid loss additive materials, as commercially obtained, often contain small amounts of acid or they start to hydrolyze to form acids when the fluids are first mixed or injected. To prevent the deleterious effects of these factors, a base or buffer was included in the fluid.
In some cases viscous fluids are used in treatments in which some or all of the fluid may be allowed to invade the formation, in which case a component is needed that is a breaker but not necessarily a fluid loss additive.
In the placement of tip screen out (TSO) fracturing treatments, it is desirable to include a fluid loss agent (FLA) to place a temporary filter cake on the faces of the fracture in the early part of the treatment, e.g., during the pad stage. Ideally, this filter cake would then be destroyed in the later stages of the treatment so that increased fluid loss during the proppant stages will allow a tip screen out to occur. The end result is a short but wide fracture with a high proppant concentration. The FLA is usually injected into the fracture with the initial pad volume used to initiate hydraulic fracturing. After the pad is injected, proppant slurry, that may also contain an FLA, is pumped into the fracture in various stages depending on job design. The proppant is designed to hold the fracture open and allow reservoir fluid to flow through the proppant pack. The proppant slurry generally includes a viscous carrier fluid to keep the proppant from prematurely dropping out of the slurry. After the proppant has been placed in the fracture, the pressure is released and the fracture closes on the proppant. However, it is necessary to remove or break both the viscosifier in the carrier fluid and the filter cake (that may contain concentrated polymer) so that reservoir fluids can thereafter flow into the fracture and through the proppant pack to the wellbore and the production string.
Conventional fracture design is well known in the art. See, e.g., U.S. Pat. No. 5,103,905, Method of Optimizing the Conductivity of a Propped Fractured Formation, assigned to Schlumberger.
Fracture clean-up issues are well recognized in the literature. Although other systems such as viscoelastic surfactants, gelled oil, slick water, etc. are used, the majority of fluids used to create the fracture and carry the proppants are polymer-based. In most reservoirs with lower permeability, the polymer concentrates as carrier fluid leaks off during the fracturing process. The concentrated polymer hinders fluid flow in the fracture and often results in underperforming fractures. Typical remedies include use of breakers, including encapsulated breakers that allow a significant increase of the breaker loading. The breaker is added to the fluid/slurry and is intended to reduce the viscosity of the polymer-based carrier fluid and facilitate fracture clean-up. Despite high breaker loading, the retained permeability of the proppant pack is still only a fraction of the initial permeability and this has been the accepted situation in the industry.
U.S. Pat. Nos. 4,848,467 and 4,961,466 discuss the use of hydroxyacetic acid and similar condensation products which naturally degrade at reservoir temperature to release acid that may be a breaker for some polymers under some conditions and which offer fluid loss control. U.S. Pat. No. 3,960,736 (Oree) discusses the use of esters to provide a delayed acid, which will break the fluid by attacking both the polymer and the borate crosslinks. Similarly, acid generation mechanisms are employed in U.S. Pat. Nos. 4,387,769 and 4,526,695 (Erbstoesser), which suggest using an ester polymer. U.S. Pat. No. 3,868,998 (Lybarger) also mentions acid generation. These references rely on acid, which generally has a relatively low activity as the breaker, but oxidative breakers are much more effective and have become the industry standard for removing polymer damage. In addition, while low pH may break borate crosslinks, it is less effective for breaking the commonly used zirconium and titanium crosslinked gels. In fact, some gel systems employing zirconium or titanium are designed to be effective viscosifiers at low pH.
As used herein, the term “breaker” refers to a chemical moiety or suite of moieties whose primary function is to “break” or reduce the viscosity of the proppant-carrying fluid. Typically in the prior art, though not always, this occurs by oxidation.
In addition, “breaker aids” are often used in conjunction with breakers to promote breaker activity. Breaker aids are disclosed in, e.g., U.S. Pat. No. 4,969,526, Non-Interfering Breaker System for Delayed Crosslinked Fracturing Fluids at Low Temperature, assigned to Schlumberger (disclosing and claiming triethanolamine); and, U.S. Pat. No. 4,250,044. Similarly, “retarding agents” (or materials designed to inhibit cross-linking) are operable in conjunction with the present invention. See, e.g., U.S. Pat. No. 4,702,848, Control of Crosslinking Reaction Rate Using Organozirconate Chelate Crosslinking Agent and Aldehyde Retarding Agent, assigned to Schlumberger (disclosing and claiming aldehydes). Copper ion, silver ion, or the like are also known to function as catalysts in conjunction with a chemical breaker, dissolved oxygen, or other oxidant source, accelerating the breaker activity. In addition, different proppant-carrying matrices can be used with different breaker types—e.g., injecting in a first stage a less viscous and/or less dense fluid followed by fluids of lesser mobility. See, e.g., U.S. Pat. No. 5,036,919, Fracturing with Multiple Fluids to Improve Fracture Conductivity, assigned to Schlumberger. U.S. Pat. No. 5,036,919 discloses, for instance, pumping a zirconate cross-linked fluid followed by a borate cross-linked fluid. Hence, it is known to use different fluids in different stages of the treatment.
SPE 68854 and SPE 91434 disclose that fibers included in the slurry of proppant in carrier fluid may serve to aid in the transport of proppant at lower viscosities and/or lower slurry flow rates, provided that fibers of the appropriate length, diameter, and stiffness are chosen and used in the right concentration.
For years fibers have been used for different purposes in oilfield treatment operations. Most recently, fiber assisted transport technology has been used to improve particle transport in fracturing and wellbore cleanout operations while reducing the amount of other fluid viscosifiers required. Recent efforts to improve this technique have looked at better ways to more completely remove fiber that can be left in the wellbore or fracture.
In commonly assigned U.S. patent application Ser. No. 11/156,966, filed Jun. 20, 2005, and Ser. No. 11/059,123, priority date Jul. 2, 2004, polyester materials such as fibers and particles are disclosed for fiber assisted transport of proppant in a fracturing method, and for fluid loss control, respectively. The polyesters can be selected from substituted and unsubstituted lactide, glycolide, polylactic acid, polyglycolic acid, copolymers of polylactic acid and polyglycolic acid, copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, and copolymers of lactic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, and mixtures of those materials. The polyester materials are naturally degraded typically 4 hours to 100 days after treatment to facilitate the restoration of permeability.
Other references that may be pertinent to the present invention include US2004/0216876; US2005/0034865; and U.S. Pat. No. 6,394,185.
Each of the references mentioned herein are hereby incorporated herein by reference in their entirety for the purpose of US patent practice and other jurisdictions where permitted.
There is a need for improved methods of placing a fluid loss control agent and removing the fluid loss control agent to restore permeability to the producing formation, especially where removal of the fluid loss control agent does not require a pH change or rely on a chemical reaction to initiate removal. Similarly, there is a need for improved methods of breaking viscosified well treatment fluids, especially employing a breaker or breaker aid that does not require changing pH or chemical reaction to activate the breaker and/or breaker aid. There is also a need for improved methods employing a fluid loss control agent or breaker that can be placed downhole in insoluble form and solubilized by salinity changes and/or by exposing the fluid loss agent or breaker to a temperature above a dissolution trigger temperature. Furthermore, there is a need for improved methods wherein a well treatment fluid additive can be used in insoluble form as a fluid loss control agent, fiber assisted proppant transfer fiber, or the like, and can then be solubilized by changing salinity conditions or exceeding a trigger temperature for removal to restore permeability, for breaking a viscosified well treatment fluid, or the like.